Method of removing non-aqueous drilling mud with banana containing fluid

ABSTRACT

Non-aqueous drilling fluids may be removed from a wellbore or tubing nor casing within the wellbore by introducing into the well a biodegradable aqueous fluid comprising banana.

FIELD

The disclosure relates to a method of removing deposits of or residuesfrom oil based or synthetic based drilling mud from a wellbore wall,tubing or casing by introducing into the well a biodegradable aqueousfluid comprising banana.

BACKGROUND

Drilling fluids (or drilling muds) carry cuttings and other particulatesoriginating during the drilling of subterranean oil and gas wells frombeneath the rotary drilling bit, through the annulus and out the well.During drilling, the fluid often remains in contact with open-holesections within the well and forms a filter cake on the formation and onsurfaces of the wellbore. Solids invasion may induce formation damage.The selection of drilling mud has a major effect on minimizing skindevelopment and maximizing oil production.

Drilling muds are normally classified according to their base fluid.Water-based muds are characterized by solid particles suspended in wateror brine. Oil can be emulsified in the water, the water being thecontinuous phase. Oil based muds (OBMs) exist either as all oil-basedmuds or as invert emulsions characterized by suspended solid particlesin the oil phase and water or brine emulsified in the oil or continuousphase. The oil of OBMs typically are petroleum materials including crudeoils as well as distilled fractions of crude oil like those produced inconventional refining operations such as diesel, kerosene and mineraloil, as well as heavy petroleum refinery liquid residues. The oil ofsynthetic based muds (SBMs) is synthesized oil and typically crude oilderivatives that have been chemically treated, altered or refined toenhance chemical or physical properties. Examples of SBMs include linearalpha olefins, isomerized olefins, poly alpha olefins, linear alkylbenzenes and vegetable and hydrocarbon-derived ester compounds. OBMs andSBMs typically form filter cakes composed of colloid particles and waterdroplets dispersed in an oil phase. Such filter cakes are hydrophobicand exhibit a permeability which is lower than the permeability of therock.

OBMs and SBMs offer performance advantages over water base fluids. Suchadvantages include higher penetration rates, improved lubricity, shalestability, decreased fluid loss, deeper bit penetration, and thinnerfilter-cake characteristics. Furthermore, fluid losses to the formationfrom OBMs and SMBs tend to be less damaging since the base fluid is oilrather than water.

After drilling is complete, a cleanup or displacement treatment toremove residues left behind by the OBMs and SBMs, including filtercakes, from the formation face is required in order to minimize skin andformation damage, increase production flow and restore the productivezone to a near-natural state. Such cleanup or displacement treatmentsbreak down the interfacial rheological properties of the filter cake,wash the damaged zone of the wellbore and restore the formation's fluidtransfer properties.

Mud removal or mud displacement procedures are usually performed beforecementing. Poor cleaning or removal of OBMs and SBMS from the wellboreor poor displacement of such muds results in solid residues and mudresidues left in the wellbore which, in turn, typically lead toformation damage, etc.

Mud residue can further reduce the quality of cement bonding during thecementing operation. Weak bonding between the cement and the formationsurface permits undesirable flow of fluids along the wellbore and aroundthe casing as well as undesirable interconnection between separateformation zones once the well is turned to production.

Remedial action for any of the above-mentioned problems, or resultingcontamination of a formation interval, can incur substantial costs inboth onshore and offshore well operations. Thus, an effective cleanoutoperation is important to secure establishment of an effective bondbetween the cement composition and the wellbore wall or tubing orcasing.

Effective clean out fluids often take the role as a spacer fluid. Spacerfluids are introduced into the well prior to a cementitious slurry andseparate or displace at least a portion of the drilling mud from an areain the wellbore into which the cementitious slurry is to be emplaced. Insome cases, the spacer fluid is capable of removing all of the drillingmud from the well prior to the pumping of the cementitious slurry. Inaddition to improving displacement efficiency of the drilling mud byseparating the mud from a physically incompatible fluid, spacer fluidscan further enhance solids removal.

Historically, aqueous-based systems have been used in the removal ordisplacement of drilling mud, including filter cakes, formed during thedrilling operation. Such aqueous systems are typically surfactant-based.Surfactant-based systems are, however, often ineffective. For instance,surfactant-based systems are typically ineffective at breaking theemulsion inside the filter cake and effecting complete phase separation.Further, aqueous surfactant-based treatments often create additionaldamage by forming an emulsion block with the formation oil. Suchemulsion blocks have the potential to block production or injection.

In addition to surfactant-based systems, solvent-based systems have alsobeen used. While strong solvency of the organic solvent toward the baseoil in OBMs often exists, organic solvents are generally expensive andoften are cost prohibitive. Further, solvent based systems are typicallynot biodegradable.

There is a need for new clean-out systems that do not cause the problemsassociated with the aqueous systems of the prior art and which furtherare biodegradable. Further, there is a need for a spacer fluid which isbiodegradable and effective in separating the OBMS from the cementslurry.

It should be understood that the above-described discussion is providedfor illustrative purposes only and is not intended to limit the scope orsubject matter of the appended claims or those of any related patentapplication or patent. Thus, none of the appended claims or claims ofany related application or patent should be limited by the abovediscussion or construed to address, include or exclude each or any ofthe above-cited features or disadvantages merely because of the mentionthereof herein.

SUMMARY

In an embodiment, the disclosure relates to a biodegradable fluid foruse in the clean-up of drilling fluids and which may function as aspacer fluid. The fluid comprises an aqueous mixture containing at leastone banana.

In another embodiment, the disclosure relates to a method of cleaning awellbore or tubing or casing in a wellbore containing residues and/ordeposits of an oil or synthetic based drilling mud. In this embodiment,an aqueous fluid containing banana is introduced into the wellbore,tubing or casing. The cleaning fluid with the drilling mud or residuesor deposits of the oil or synthetic based drilling mud entrained in thecleaning fluid is then removed from the wellbore, tubing or casing.

In another embodiment, a method of removing at least a portion ofoil-based or synthetic based mud or deposits or residues thereof from awellbore is provided. In this embodiment, an aqueous fluid containing atleast one banana is introduced into wellbore, after the wellbore hasbeen drilled with the oil-based or synthetic based mud. The oil-based orsynthetic-based mud, deposits or residues thereof is then removed fromthe wellbore with the banana.

In another embodiment, a method of removing a filter cake of a drillingmud, deposits or residues thereof from a wellbore is provided wherein abiodegradable aqueous fluid comprising water and banana is introducedinto the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

A, B and C of the Figure illustrate the efficiency of an aqueous fluidcontaining a mixture of water and banana in the removal of oil-baseddrilling mud wherein A is a rotor sleeve after rotating in oil-baseddrilling fluid, B are prior art surfactant washes and C is the aqueousbanana-containing fluid.

DETAILED DESCRIPTION

Characteristics and advantages of the present disclosure and additionalfeatures and benefits will be readily apparent to those skilled in theart upon consideration of the following detailed description ofexemplary embodiments of the present disclosure and referring to theaccompanying figure. It should be understood that the descriptionherein, being of exemplary embodiments, are not intended to limit theclaims. On the contrary, the intention is to cover all modifications,equivalents and alternatives falling within the spirit and scope of theclaims. Changes may be made to the particular embodiments and detailsdisclosed herein without departing from such spirit and scope.

As used herein, the terms “disclosure”, “present disclosure” andvariations thereof are not intended to mean every possible embodimentencompassed by this disclosure or any particular claim(s). Thus, thesubject matter of each such reference should not be considered asnecessary for, or part of, every embodiment hereof or of any particularclaim(s) merely because of such reference.

Certain terms are used herein and in the appended claims to refer toparticular components. As one skilled in the art will appreciate,different persons may refer to a component by different names. Thisdocument does not intend to distinguish between components that differin name but not function. Also, the terms “including” and “comprising”are used herein and in the appended claims in an open-ended fashion, andthus should be interpreted to mean “including, but not limited to . . ..” Further, reference herein and in the appended claims to componentsand aspects in a singular tense does not necessarily limit the presentdisclosure or appended claims to only one such component or aspect, butshould be interpreted generally to mean one or more, as may be suitableand desirable in each particular instance.

All ranges disclosed herein are inclusive of the endpoints. Unlessstated otherwise, any range of values within the endpoints isencompassed. For example, where the endpoints of a range are stated tobe from 1 to 10, any range of values, such as from 2 to 6 or from 3 to 5will be defined by the range. The suffix “(s)” as used herein isintended to include both the singular and the plural of the term that itmodifies, thereby including at least one of that term. All referencesare incorporated herein by reference.

The use of the terms “a” and “an” and “the” and similar referents in thecontext of describing the invention (especially in the context of thefollowing claims) are to be construed to cover both the singular and theplural, unless otherwise indicated herein or clearly contradicted bycontext.

The term “tubing” as used herein shall refer to any surface to whichdrilling mud is in contact during the transport of drilling mud, oil orgas from the well to the surface. It shall include liners, coiledtubing, tubing string, etc.

As used herein, the term “drilling fluid” or “drilling mud” furtherencompasses drill-in fluids.

The word “banana” shall refer to a whole banana which includes the peelas well as the edible portion of the fruit.

The aqueous fluid disclosed herein may be referred to as a cleaningfluid or a displacement fluid for use in removing or displacing OBMs andSBMs (including deposits, such as filter cakes, and residues thereof)from wellbore walls, tubings and casings.

The aqueous fluid fluidly contacts a portion of the tubular exteriorsurface and a portion of the wellbore wall of the annulus. The aqueousfluid contacting the surfaces makes both surfaces water-wet and inducescirculation of flow of the drilling mud in the wellbore and into thewellbore annulus.

In an embodiment, the aqueous fluid displaces SBMs and OBMs from theannulus and casing as well. In addition, the aqueous fluid increases theproduction of hydrocarbons from oil and gas wells. The well may be ahorizontal, vertical or deviated well.

The aqueous fluid is highly efficacious in breaking down the interfacialrheological properties of OBM and SBM mud cakes for diversified drillingmud systems. In an embodiment, the aqueous fluid separates the OBM orSBM into its component phases by breaking (demulsifying) the emulsioninside the filter cake. For example, the aqueous fluid is capable offlocculating water droplets of the mud systems. During flocculation, thedroplets clump together forming aggregates or flocs. Water droplets fuseto form larger drops during coalescence. This leads to complete phaseseparation (oil and water) and emulsion breaking. Filter cake cohesionand wellbore adherence of the mud decreases.

The efficiency of the aqueous fluid is evidenced by the high percentageof filter cake removal. The amount of filter cake and residual mudremoved from the well from a single treatment is typically higher than80% and more typically in excess of 90%.

The fluid comprises water and banana. The banana may be combined withthe water whole or may be pulverized or fragmented when added to water.Typically, the banana is combined with the water and the mixture thensubjected to mixing or shear.

The aqueous fluid system does not require a surfactant and does not forman emulsion.

The fluid systems are biodegradable and exhibit very low, if any,toxicity to the environment and aquatic organisms (including those lowin the food chain). Thus, the fluid systems are environmentally friendlyand, while exhibiting superior excellent cleaning performance,demonstrate a clear eco-toxicological advantage over conventionalcleaning fluids.

The aqueous fluid may be supplied in a concentrate form and then admixedwith water before use. In an embodiment, the concentrate may be admixedwith up to about 90 weight percent water prior to use. Typically, whenintroduced into the well, the fluid contains a weight ratio ofbanana:water between from about of from about 1:10 to about 10:1, moretypically from about 1:5 to about 5:1. In a preferred embodiment, theweight ratio of banana to water is about 1:1. In an embodiment, a mostefficient cleaning fluid may be obtained where the amount of banana inthe fluid is from about 0.5 to 20% by weight, preferably from 1 to 10%by weight, more preferably from 3 to 8% by weight of the aqueous fluid.Prior to being introduced into the well, a viscosifying agent (asreferenced herein as well as other conventional additives) may be addedto the fluid, fluid.

The water of the aqueous fluid may be hard or soft, and may be freshwater or salt water. Sea water may be used in those instances where thesupply of fresh water is limited. Brines may also be used to dilute aconcentrate before introduction into the well.

In an embodiment, a concentrate of the fluid may be shipped to itsdestination and then admixed with water to the desired ratios. Suchadmixing may occur on the fly.

In another embodiment, a concentrated form of the banana may be injectedinto the well and diluted in situ in an aqueous fluid present in thewellbore, tubing or casing.

The aqueous fluid is stable over a relatively wide range of temperatures(typically up to 300° F. or higher), is tolerant of both caustic andacidic fluids and further is tolerant over a relatively wide range offluid salinity. This is important since fluid remaining in the wellboreafter completion of the drilling and casing process may contain asignificant amount of brine.

Typically, the pH of the aqueous fluid pumped into the well is neutral,typically from about 6.0 to about 10.0.

The breaking down of the OBM or SBM and the cleaning efficiency of thefluid may be enhanced when the aqueous fluid is subjected to eitherlaminar or turbulent flow conditions.

In addition to enhancing the removal of residues of OBMs and SBMs fromthe well, the aqueous fluid may be used as a displacement or spacerfluid to separate the mud from a physically incompatible cementitiousslurry. In this embodiment, the spacer fluid may be introduced into thewellbore having a first fluid (drilling mud) disposed therein. A secondfluid (cementitious slurry) may be introduced into the wellbore with thespacer fluid separating the first fluid and the second fluid.

In a preferred operation, the spacer fluid may be pumped down thewellbore and up through the annulus between the casing and the formationface to remove or displace at least a portion of the drilling mud fromthe wellbore and into the annulus.

Introduction of the aqueous fluid into the wellbore may occur through afirst fluid conduit at a pressure adequate to induce laminar orturbulent fluid circulation such that an equivalent amount of wellborefluid (mud) is displaced through a second fluid conduit. Here, thewellbore annulus forms between the external surface of the tubular(having the internal fluid conduit and an external surface) and thewellbore wall. The internal fluid conduit fluidly couples the surfacewith the wellbore. After the mud has been displaced by the aqueousfluid, a water-based cement slurry may be introduced into the conduitand the slurry cured. (In some instances, the cement slurry may befollowed by an additional volume of the spacer fluid.) The spacer fluidis introduced into the wellbore in an amount sufficient to separate thedrilling mud from the cement slurry. As the spacer fluid is circulatedthrough the wellbore, it mixes with the drilling mud. Before thedrilling mud is completely removed from the area to be cemented, theremay be some mixing of the drilling mud, spacer fluid and cement slurry.However, the spacer fluid will not harden, gelatinize or otherwisebecome immobile because of the commingling of the three components. Thecured cement is separated from the mud by the aqueous or space fluid;the spacer fluid isolating at least a portion of the wellbore annuluscontaining the drilling mud from the aqueous cement slurry.

In an embodiment, positioning the aqueous slurry in the wellbore annulusoccurs such that the cement slurry contacts both the tubular externalsurface and the wellbore wall. Maintaining the position of the aqueouscement slurry permits the cement to adhere to the water-wet surfaces ofthe wellbore wall and tubular exterior. It also permits the wellboreconditions to induce curing in the cement. Upon curing, the aqueouscement slurry forms a solid cement material in the wellbore annulus,fluidly isolating at least a portion of the wellbore annulus.

Ideally, the spacer fluid removes all of the drilling mud,dehydrated/gelled drilling mud and residues therefor (including filtercakes) from the well prior to the pumping of the cementitious slurry.Where this is not the case, and the drilling mud and aqueous cementslurry are not compatible with each other, the aqueous fluid as adisplacement or spacer fluid serves to separate or prevent contactbetween them and to remove the drilling mud from the area in which thecement slurry is to be emplaced. Negative direct interaction between thedrilling mud (the first fluid) and the cementitious slurry is avoided.Cementing in the presence of filter cake can cause a cementing job tofail. The adhesion of filter cake and gelled fluid to the well bore wallor the tubular exterior is weak compared to the bond that cement canmake. Cementing on top of filter cake strips the cake off the walls andexterior surfaces due to the weight of the cement upon curing. This lackof direct adhesion creates fluid gaps in and permits circulation throughthe well bore annulus. Thus, the spacer fluid defined herein may be usedto remove such composition.

The cement of the cement slurry may be any conventional cement used inthe art in the cementing of wells. Such cements include those comprisingcalcium, aluminum, silicon, oxygen, iron, and/or sulfur, which set andharden by reaction with water as well as hydraulic cements such asPortland cements, pozzolan cements, gypsum cements, high alumina contentcements, slag cements, silica cements as well as combinations thereof.

The aqueous fluid as spacer fluid may also useful for separatingdifferent drilling muds during drilling mud change outs and forseparating a drilling mud and an aqueous fluid (including a completionbrine or seawater) during well integrity testing. In some instances, theaqueous fluid may water-wet surfaces of the wellbore to promote bondingof the cement sheath to the wellbore and casing.

The efficiency of the aqueous fluid as a spacer fluid is improved by thefluid being compatible at downhole temperatures and pressures with bothOBM and SBM muds as well as cementitious slurries.

The aqueous fluid may further include a viscosifying agent as rheologymodifier. The aqueous fluid may be formed by blending the viscosifyingagent (and any of the components referenced herein) into the aqueousfluid containing the banana. Blending means can include mixing using alow- or high-shear blender; batch mixing of the components may proceeduntil homogeneous incorporation and formation of the fluid is obtained.The aqueous fluid may be prepared on the fly.

The viscosifying agent may induce thickening of the fluid to enableparticle suspension and provide salinity and long-term fluidity to thefluid. The enhanced stability enables the aqueous fluid to be used atelevated bottom hole temperatures. In an embodiment, the aqueous fluidis stable and may be used at a bottom hole temperature 300° F. andhigher. In another embodiment, the fluid is stable and may be used at abottom hole temperature of 400° F. and higher. The viscosifying agentmay further assist in the prevention of losses of the aqueous fluid intothe formation.

In an embodiment, the viscosifying agent may be added to the aqueousfluid containing the banana or the banana may be added to a fluidalready viscosified by the viscosifying agent.

The viscosifying agent may be included in the aqueous fluid in an amountsufficient to provide, for example, the desired rheological properties.Typically, the amount of viscosifying agent in the aqueous fluid isbetween from between 0 to about 50 weight percent of the total weight ofthe aqueous fluid, preferably no more than about 20 or 30 pounds per1,000 gallons of water.

The viscosifying agent may be a phosphomannan, dextran, starch, starchderivative, polysaccharides, such as xanthan, derivatized xanthan, welangums, locust bean gum, karaya gum, diutan, galactomannan gums, cellulosegums, corn, potato, wheat, maize, rice, cassava, and other foodstarches, cornstarch, hydroxyethyl cornstarch, hydroxypropyl cornstarch,succinoglycan, scleroglucan and carrageenan and mixtures thereof. Theviscosifying agent may further be a synthetic polymer such as apolyvinyl alcohol or an ammonium or alkali metal salt of anacrylamidomethylpropanesulfonic acid as well as mixtures thereof.

Preferred cellulosic derivatives include hydroxyethyl cellulose,hydroxypropyl cellulose, carboxymethylhydroxyethyl cellulose,ethylhydroxyethyl cellulose, ethylmethylhydroxyethyl cellulose,hydroxypropyl methyl cellulose, hydroxyethylpropyl cellulose, dialkylcarboxymethyl cellulose, and carboxymethyl cellulose, alkyl cellulosessuch as methyl cellulose and mixtures thereof. Hydroxyethyl cellulose isespecially preferred.

Galactomannan gums include underivatized guar as well as derivatizedguars like hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar(CMHPG).

The viscosifying agent may be crosslinkable or non-crosslinkable and maybe considered as a thickening polymer which is hydratable to form alinear or crosslinked gel.

The density of the aqueous fluid may be dependent upon well conditions,most specifically, the density of the mud in the wellbore at the time ofcementation. It is preferable, but not essential, that the fluidintroduced into the wellbore have a density at least equal to or greaterthan the density of the drilling mud and, when used as a spacer fluid,less than or equal to the density of the cementitious slurry to beintroduced into the wellbore. The higher density spacer fluid pushesgelled and solid remnants of the displaced fluid away from the wellborewall and fluid conduit exteriors.

In an embodiment, the aqueous fluid may be characterized by a densityranging from about 8 to about 24 lb/gal, more preferably from about 14to about 20 lb/gal, and most preferably about 16 to 20 lb/gal.

The aqueous fluid may contain one or more weighting agents to increasethe density of the fluid. For instance, when used as a spacer fluid, theweighting agent may increase the density profile between the fluids itis separating and to prevent fluid inversion with other fluids in thewellbore. The weighting agent is employed in an amount sufficient toprovide the desired density to the aqueous fluid. Typically, theweighting agent is present in the aqueous fluid in a range of from about100 pounds to about 400 pounds per barrel of base aqueous fluid. Theweighting agent also assists with increasing the buoyancy effect of theaqueous fluid on gelled drilling muds and filter cake. The weightingagent may be part of the aqueous fluid introduced into the wellbore ormay be applied subsequent to the introduction of the aqueous fluid intothe wellbore.

Weighting agents that can be utilized are preferably insoluble in waterand liquid hydrocarbons and include sand, barite, hematite, fly ash,calcium carbonate, silica sand, illmanite, manganese oxide, trimanganesetetraoxide, iron oxide, and fly ash and the like. Barite is especiallypreferred.

The aqueous fluid may contain one or more other components tosecondarily supplement desirable properties of the fluid. When present,the amount of any of such components may be in the range of from about0.05% to about 1%, more typically between about 0.2 and about 0.5%, andmost typically about 0.3%, by weight.

For instance, the aqueous fluid may contain an antifoaming agent toreduce surface tension and prevent the formation of foams and emulsionsfrom forming between the aqueous spacer fluid and hydrocarbons in thedrilling mud and in the wellbore interior. Suitable antifoaming agentsmay include polysiloxanes, paraffinic oils, mineral oils, vegetable oilsas well as combinations thereof.

The aqueous fluid may contain a suspension agent in order to maintainthe fluid with minimal separation over time and to impart the requisiteviscosity to the fluid to allow weighting particles to remain suspendedover a period of time. Typically, the suspension agent is hydrated inwater for a time sufficient to obtain the desired viscosity of thesolution. Suitable suspending agents may include starch, succinoglycan,polyethylene oxide, oil in water emulsions created with paraffin oil,carrageenan, etc.

Further, the spacer fluid may contain a thinning agent for reducing flowresistance and gel development by reducing viscosity of the aqueousfluid. For instance, the thinning agent may reduce the flow resistanceand gel development of a filter cake. Functional groups on the thinningagents may act to emulsify oils and hydrocarbons present in the aqueousphase. Thinning agents may also be used in the aqueous fluid to attractsolids and particles and disperse such particles; the dispersion ofparticles preventing any increase in viscosity of the spacer fluid dueto aggregation. The thinning agent may further interact with chargedparticles in the wellbore fluid to suspend them for removal from thewellbore. Thinning agents, which are ionic, can further counter-act theeffects of cement slurry intrusion into the aqueous fluid. (Cementintrusion in the spacer fluid composition can result in greater salineconcentration or higher pH, which in turn can cause the gel strength orthe yield point value, or both, of the spacer fluid to rise.) Suitablethinning agents include tannins, lignins, and humic acids,

In some instance, a salt may be added to the fluid to reduce the amountof water needed and also lowers the freezing point of the aqueous fluid.Among the salts that may be added are NaCl, KCl, CaCl₂), and MgCl₂.Other suitable salts can be formed from K, Na, Br, Cr, Cs and Bi metals.

A wide variety of additional additives may also be included in theaqueous fluid as deemed appropriate by one skilled in the art, with thebenefit of this disclosure. Examples of such additives include freewater control additives, fluid loss control additives, lost circulationmaterials, filtration control additives, dispersants, defoamers,corrosion inhibitors, anti-microbial inhibitors, anti-foaming agents,scale inhibitors, formation conditioning agents, etc.

Examples

All percentages set forth in the Examples are given in terms of volumeunits except as may otherwise be indicated.

Example 1. A rotor test was conducted at ambient temperature to compareconventional spacer fluids with a biodegradable aqueous fluid containingbanana. The banana fluid contained about 100 g of banana (includingpeel) and 100 g of water. The comparative fluids were a Surfactant wash(base line) having a 50:50 weight ratio of water and spacer surfactant.A second fluid (“Surfactant wash with LCM 1”) containing the Surfactantwash and 2 percent by weight of a commercial fibrous loss circulationmaterial (LCM 1). A third fluid (“Surfactant wash with LCM 2”)containing the Surfactant wash and 2 percent by weight of a commercialloss circulation material (LCM 2).

The rotor test for determining water-wetting of the fluid was undertakenby first loading the oil-based drilling fluid into a rheology cup. Thecup was then placed on the base and raised upward slowly until thedrilling fluid was even with the line inscribed on the outer surface ofthe rotary sleeve. The cup was then rotated at 100 rpm for about 5minutes. The sleeve after rotating in the oil-based drilling fluid isshown in A of the Figure. The drilling fluid cup was then removed andexcess fluid was allowed to drip from the sleeve. The test fluid wasthen loaded into a clean rheology cup. The cup was placed on the baseand raised upward slowly until the fluid was even with the lineinscribed on the outer surface of the rotary sleeve. The cup was thenrotated at 100 rpm in 1, 2, 5 and 10 minute intervals. The cup was thenremoved and visually observed and the cleanliness of the sleeve was thenrecorded. The water was then loaded into a clean rheology cup. The cupwas then placed on the base and raised upward slowly until the water waseven with the line inscribed on the outer surface of the rotary sleeve.The cup was then rotated at 100 rpm for about 5 minutes. The cup wasremoved and visually observed. The cleanliness of the sleeve was thenrecorded. The results for the Surfactant wash, Surfactant wash with LCM1 and Surfactant wash with LCM 2 are shown in B of the Figure. Thesleeve after rotating in the mixture of banana and water after 1 minuteis shown in C of the Figure. As illustrated in C of the Figure, thebanana mixture was shown to be more efficient within one minute versusthe 10 minutes of the commercial spacer packages. As illustrated, theaqueous fluid containing mixture was almost 90% visibly more efficientthan the commercial spacer packages.

The methods that may be described above or claimed herein and any othermethods which may fall within the scope of the appended claims can beperformed in any desired suitable order and are not necessarily limitedto any sequence described herein or as may be listed in the appendedclaims. Further, the methods of the present disclosure do notnecessarily require use of the particular embodiments shown anddescribed herein, but are equally applicable with any other suitablestructure, form and configuration of components.

Embodiment 1. A method of cleaning a wellbore or tubing or casing in awellbore containing residues of oil or synthetic based drilling muds,the method comprising introducing into the wellbore, tubing or casing anaqueous cleaning fluid containing banana and removing from the wellbore,tubing or casing the cleaning fluid having at least a portion of theresidues and deposits entrained therein.

Embodiment 2. The method of embodiment 1, further comprising introducinginto the wellbore, tubing or casing a cementitious slurry and displacingat least a portion of the drilling mud, drilling mud deposits ordrilling mud residues with the aqueous fluid.

Embodiment 3. The method of embodiment 1 or 2, wherein at least aportion of the drilling mud, drilling mud deposits or drilling mudresidues are displaced out of the well with the aqueous fluid.

Embodiment 4. The method of embodiment 3, wherein all of the drillingmud, drilling mud deposits or drilling mud residues are displaced out ofthe well with the aqueous fluid.

Embodiment 5. The method of any of embodiments 1 to 4, wherein theaqueous fluid further comprises a weighting agent.

Embodiment 6. The method of any of embodiments 1 to 5, wherein thedensity of the aqueous fluid is from about 8 to about 24 lb/gal.

Embodiment 7. The method of any of embodiments 1 to 6, furthercomprising diluting a concentrate of a fluid containing banana to renderthe aqueous cleaning fluid and then introducing the aqueous cleaningfluid into the wellbore, tubing or casing.

Embodiment 8. The method of embodiment 7, wherein the concentrate isdiluted on the fly.

Embodiment 9. The method of any of embodiments 1 to 8, wherein thebanana weight ratio of banana:water in the aqueous cleaning fluid isfrom about 1:10 to about 10:1.

Embodiment 10. The method of embodiment 9, wherein the weight ratio ofbanana:water in the aqueous cleaning fluid is from about 1:5 to about5:1.

Embodiment 11. The method of embodiment 10, wherein the weight ratio ofbanana:water in the aqueous cleaning fluid is 1:1.

Embodiment 12. A method of removing at least a portion of oil-based orsynthetic based mud or deposits or residues thereof from a wellborecomprising (a) introducing into the wellbore, after the wellbore hasbeen drilled with the oil-based or synthetic based mud, an aqueous fluidcomprising banana; and (b) removing the oil-based or synthetic-basedmud, deposits or residues thereof from the wellbore with banana.

Embodiment 13. The method of embodiment 12, further comprisingintroducing into the wellbore, tubing or casing a cementitious slurryand displacing at least a portion of the drilling mud, drilling muddeposits or drilling mud residues with the aqueous fluid.

Embodiment 14. The method of embodiment 12 or 13, wherein the aqueousfluid further comprises a weighting agent, a viscosifying agent or amixture thereof.

Embodiment 15. A method of removing a filter cake of a drilling mud,deposits or residues thereof from a wellbore comprising comprisesintroducing a biodegradable aqueous fluid into the wellbore, the fluidcomprising water and banana.

Embodiment 16. The method of embodiment 15, wherein, prior to step (a),a concentrate of banana diluted in water to form the biodegradableaqueous fluid.

Embodiment 17. The method of embodiment 15 or 16, wherein the aqueousfluid further comprises a weighting agent, viscosifying agent or acombination thereof.

Embodiment 18. The method of any of embodiments 15 to 17, wherein theconcentrate is diluted on the fly.

Embodiment 19. The method of any of embodiments 15 to 18, wherein theweight ratio of banana:water in the aqueous cleaning fluid is from about1:10 to about 10:1.

Embodiment 20. The method of embodiment 19, wherein the weight ratio ofbanana:water in the aqueous cleaning fluid is from about 1:5 to about5:1.

What is claimed is:
 1. A method of cleaning a wellbore or tubing orcasing in a wellbore containing residues and/or deposits of an oil orsynthetic based drilling mud, the method comprising: (a) introducinginto the wellbore, tubing or casing an aqueous fluid containing bananawherein the weight ratio of banana:water in the aqueous fluid containingbanana is from about 1:10 to about 10:1; (b) separating oil and waterphases of the oil or synthetic based drilling mud with the aqueous fluidcontaining banana; and (c) removing from the wellbore, tubing or casingfluid having residues or deposits of the oil or synthetic based drillingmud entrained therein.
 2. The method of claim 1, further comprisingintroducing into the wellbore, tubing or casing a cementitious slurryand displacing at least a portion of the drilling mud, drilling muddeposits or drilling mud residues with the aqueous fluid containingbanana.
 3. The method of claim 1, wherein at least a portion of thedrilling mud, drilling mud deposits or drilling mud residues aredisplaced out of the well with the aqueous fluid containing banana. 4.The method of claim 1, wherein the aqueous fluid containing bananafurther comprises a weighting agent.
 5. The method of claim 1, whereinthe density of the aqueous fluid containing banana is from about 8 toabout 24 lb/gal.
 6. The method of claim 1, wherein the aqueous fluidcontaining banana introduced into the wellbore, tubing or casing isdiluted from a concentrate of a fluid containing the banana.
 7. Themethod of claim 6, wherein the concentrate is diluted on the fly.
 8. Themethod of claim 1, wherein the weight ratio of banana:water in theaqueous fluid containing banana is from about 1:5 to about 5:1.
 9. Themethod of claim 8, wherein the weight ratio of banana:water in theaqueous fluid containing banana is 1:1.
 10. The method of claim 1,wherein the amount of banana in the aqueous fluid containing bananaintroduced into the wellbore, tubing or casing is from about 0.5 toabout 20% by weight.
 11. The method of claim 1, wherein the aqueousfluid containing banana introduced into the wellbore, tubing or casingcontains pulverized or fragmented banana.
 12. A method of removing atleast a portion of oil-based or synthetic based mud or deposits orresidues thereof from a wellbore comprising: (a) introducing into thewellbore, after the wellbore has been drilled with the oil-based orsynthetic based mud, an aqueous fluid comprising edible banana fruit andbanana peel wherein the weight ratio of both edible banana fruit andbanana peel to water in the aqueous fluid is from about 1:10 to about10:1; and (b) removing the oil-based or synthetic-based mud, deposits orresidues thereof from the wellbore with the aqueous fluid comprisingedible banana fruit and banana peel.
 13. The method of claim 12, furthercomprising introducing into the wellbore, tubing or casing acementitious slurry and displacing at least a portion of the drillingmud, drilling mud deposits or drilling mud residues with the aqueousfluid comprising edible banana fruit and banana peel.
 14. The method ofclaim 12, wherein the aqueous fluid comprising edible banana fruit andbanana peel further comprises a weighting agent, a viscosifying agent ora mixture thereof.
 15. The method of claim 12, wherein the aqueous fluidcomprising edible banana fruit and banana peel introduced into thewellbore, tubing or casing contains pulverized or fragmented ediblebanana fruit and banana peel.
 16. A method of removing a filter cake ofan oil or synthetic based drilling mud, deposits or residues thereoffrom a wellbore comprising (a) introducing a biodegradable aqueous fluidinto the wellbore, the biodegradable aqueous fluid comprising water,edible banana fruit and banana peel, wherein the weight ratio of bothedible banana fruit and banana peel to water in the biodegradableaqueous fluid is from about 1:10 to about 10:1; and (b) decreasingcohesion of the filter cake with the biodegradable aqueous fluid. 17.The method of claim 16, wherein, prior to step (a), diluting aconcentrate of fluid containing the edible banana fruit and banana peelin water to form the biodegradable aqueous fluid.
 18. The method ofclaim 17, wherein the concentrate is diluted on the fly.
 19. The methodof claim 16, wherein the biodegradable aqueous fluid further comprises aweighting agent, viscosifying agent or a combination thereof.
 20. Themethod of claim 16, wherein the weight ratio of both edible banana fruitand banana peel to water in the biodegradable aqueous fluid is fromabout 1:5 to about 5:1.